Fields of Disclosure
The disclosure relates generally to the field of fluid separation. More specifically, the disclosure relates to the cryogenic separation of contaminants, such as acid gas, from a hydrocarbon.
Description of Related Art
This section is intended to introduce various aspects of the art, which may be associated with the present disclosure. This discussion is intended to provide a framework to facilitate a better understanding of particular aspects of the present disclosure. Accordingly, it should be understood that this section should be read in this light, and not necessarily as admissions of prior art.
The production of natural gas hydrocarbons, such as methane and ethane, from a reservoir oftentimes carries with it the incidental production of non-hydrocarbon gases. Such gases include contaminants, such as at least one of carbon dioxide (“CO2”), hydrogen sulfide (“H2S”), carbonyl sulfide, carbon disulfide and various mercaptans. When a feed stream being produced from a reservoir includes these contaminants mixed with hydrocarbons, the stream is oftentimes referred to as “sour gas.”
Many natural gas reservoirs have relatively low percentages of hydrocarbons and relatively high percentages of contaminants. Contaminants may act as a diluent and lower the heat content of hydrocarbons. Some contaminants, like sulfur-bearing compounds, are noxious and may even be lethal. Additionally, in the presence of water some contaminants can become quite corrosive.
It is desirable to remove contaminants from a stream containing hydrocarbons to produce sweet and concentrated hydrocarbons. Specifications for pipeline quality natural gas typically call for a maximum of 2-4% CO2 and ¼ grain H2S per 100 scf (4 ppmv) or 5 mg/Nm3 H2S. Specifications for lower temperature processes such as natural gas liquefaction plants or nitrogen rejection units typically require less than 50 ppm CO2.
The separation of contaminants from hydrocarbons is difficult and consequently significant work has been applied to the development of hydrocarbon/contaminant separation methods. These methods can be placed into three general classes: absorption by solvents (physical, chemical and hybrids), adsorption by solids, and distillation.
Separation by distillation of some mixtures can be relatively simple and, as such, is widely used in the natural gas industry. However, distillation of mixtures of natural gas hydrocarbons, primarily methane, and one of the most common contaminants in natural gas, carbon dioxide, can present significant difficulties. Conventional distillation principles and conventional distillation equipment are predicated on the presence of only vapor and liquid phases throughout the distillation tower. The separation of CO2 from methane by distillation involves temperature and pressure conditions that result in solidification of CO2 if a pipeline or better quality hydrocarbon product is desired. The required temperatures are cold temperatures typically referred to as cryogenic temperatures.
Certain cryogenic distillations can overcome the above mentioned difficulties. These cryogenic distillations provide the appropriate mechanism to handle the formation and subsequent melting of solids during the separation of solid-forming contaminants from hydrocarbons. The formation of solid contaminants in equilibrium with vapor-liquid mixtures of hydrocarbons and contaminants at particular conditions of temperature and pressure takes place in a controlled freeze zone section.
Some cryogenic distillation methods include a process to collect a liquid stream in a tray, heat the liquid stream to form a vapor, and re-introduce the vapor into the distillation process. FIGS. 1 and 2 show a portion of a fractionation column 1 designed to perform such a process. A heated vapor stream is introduced into the column 1 via inlets 2. The vapor rises through risers or chimneys 3 and heats other portions of the cryogenic distillation process. Cooled vapor descends as liquid between chimneys 3 and falls on a draw tray deck, otherwise known as a chimney tray 4. All or part of the liquid may be collected. Liquid on the chimney tray 4 is directed to a centralized collection trough 5 that equalizes the flow of the collected liquid to a collection sump(s) 6 through outlet nozzles 7 that are cut into the wall 8 of the fractionation column 1 Outlet nozzles allow the liquid to transfer from the sump(s) 6 to the downcomer piping 9 and thereby exit the fractionation column 1
Conventional design practice limits the chimney tray 4 to accommodate either one or two outlet nozzles 7 through which the collected liquid passes out of the column and into the downcomer piping. If two outlet nozzles 7 are used, the outlet nozzles almost always are oriented at 180 degrees from each other, as shown in FIGS. 1 and 2. The outlet nozzles 7 may be positioned several feet above ground to provide a liquid static head, or pressure, in the downcomer piping 9 for required pump performance and/or desired heat exchanger operation. However, a constant head in the downcomer piping may not be possible if more than two outlet nozzles are used. Additionally, as sump extends into the fractionation column 1, the available diameter for fluid and vapor flow inside the fractionation column is reduced.
A need exists for improved technology that permits more than two outlet nozzles to be employed in a chimney tray assembly.
A need also exists for improved technology that reduces or eliminates the constriction or reduced diameter for fluid and/or vapor flow in a fractionation column due to a sump.